A wellhead may be classified by the American Petroleum Institute (API) as an independent screwed wellhead according to features discussed in the published Specification 6A. Generally, an independent screwed wellhead has an "independently" secured wellhead body, such as a casing head or a tubing head, for each tubular string disposed within the wellbore. The pressure within the casing is temporarily controlled by a blowout preventer (BOP) conventionally provided above the wellhead. The tubing head may be "independently" secured to a respective tubular string, and is not directly flanged or similarly connected to the casing head. Each independent wellhead body is secured to a respective tubular string, and a smaller diameter production tubular string generally extends through the wellhead body.
More specifically, an independent screwed wellhead may utilize a lower casing head body that is threaded or socket welded onto the upper end of a surface casing. This lower casing head body may carry a slip assembly or other means to support a production string that is concentrically disposed within the surface casing. One or more ports in the casing head body provide communication to the interior of the surface casing string. The casing string may extend downwardly into the wellbore for only a portion of the depth of the wellbore, although the production tubing string will typically extend downwardly to the desired depth in the wellbore. The top end of the production casing string may extend upwardly from the slip assembly in the casing head body and may be threaded at its upper end to another "independent screwed" wellhead body. In a similar manner, a tubular string may extend through this second wellhead body, supported by a second set of slips within the second wellhead body. A third wellhead body or tubing head may be "independently screwed" on top of this tubular string. Thus, additional strings of concentric tubulars may be utilized, and each string may have an independent wellhead body attached thereto.
Since the wellhead bodies, such as the tubing head body and casing head body, are generally not in physical contact with each other, they are classified as "independent". As well, the independent screwed casing head is not dependent upon the tubing head to seal off the annulus between the surface casing and the production tubing. A packing member may be provided above each slip assembly in a wellhead to selectively seal the annulus surrounding the tubing and in fluid communication with one or more side ports in the wellhead. Devices other than slips and packing members may be used for supporting a string of tubular goods and for sealing with the independent screwed wellhead body.
"Working pressure rating" means the highest pressure that the device is designed to withstand on a regular basis. The working pressure rating or capability of the independent screwed wellhead is relatively low, and typically is the range of about 3000 psi or less. This lower working pressure rating is sufficient to provide pressure control for many wells over their entire lifetime. Most importantly, the cost of the independent screwed wellhead is typically much lower than the cost of wellheads with flanges. For safety purposes, the working pressure capability of a wellhead will be greater than the pressure it is expected to handle.
The ranged casing head generally meets the standards of API Specification 6A or may have dimensionally compatible flanges meeting the requirements of the American National Standards Institute (ANSI). In a ranged wellhead, flanges disposed on the surface casing wellhead body and production tubing wellhead body are secured together. Because the flanges are in contact, they are not "independent". As well, it is necessary to secure the flanges together to form an annular seal. The ranged tubing head may have a lower recess or socket with a rubber seal therein that slides over the protruding tubular string until both flanges mate. The flanged casing head is therefore dependent upon the lower flange of the tubing head, and more specifically on the seal between the two flanges, to achieve a complete seal between the surface casing and the production casing. The ranged casing head and tubing head employ massive flanges, and therefore are significantly more expensive than the independent screwed wellheads.
The terms "tubing" and "casing" do not intrinsically describe a specific tubular member but more accurately reflect the purpose to which the tubular good is applied. As a very general rule, casing typically is a tubular with a nominal outside diameter of about 41/2 inches or more. Tubing is typically a tubular with a nominal outside diameter of less than about 41/2 inches. It will be understood herein that strings of "tubulars", "tubular goods", "tubular members", and the like may refer to various types of surface casing strings, production casing strings, and/or tubing strings.
A blowout preventer (BOP) is typically mounted on the wellhead, regardless of whether an independent screwed or ranged wellhead is utilized. The BOP is used during drilling and completion operations to control any pressure buildup that may occur in the well. The BOP is typically required as a safety precaution even when drilling and completing shallow, low pressure wells.
Most BOPs in use today have a massive API bottom flange designed to mate with the ranged casing head. An adapter flange, also known as a drilling flange, may be used to temporarily mate an independent screwed casing head with the bottom flange of a BOP. The production casing string and/or tubing string is typically run through the BOP. The BOP is conveniently installed above the casing head so that the casing or tubing hanger mechanism can be set while pressure in the annulus is controlled by the BOP.
Flanged wellheads were initially developed for high pressure operations, and are frequently designed for pressures in excess of 10,000 psi. Flanged wellheads commonly have at least a 5000 psi working pressure rating. A 5000 psi working pressure rating ranged wellhead may cost two to four times as much as a 3000 psi rated independent screwed wellhead. The well operator will therefore normally prefer utilizing an independent screwed wellhead unless it is anticipated that higher pressures will be encountered.
In many situations, operators anticipate encountering pressures above 3000 psi only-for a very short period of time. For instance, a well that requires a formation fracturing operation to complete the well will require high pressures for about one or two hours to break down or fracture a downhole formation. During the remainder of the life of the well, only relatively low pressures below 2000 psi may be anticipated. A lower working pressure independent screwed wellhead with a rating of 3000 psi would accordingly be suitable except for the short duration high pressure fracturing operation. Nevertheless, a high pressure flanged wellhead is typically used because of the high pressure associated with the temporary fracturing operation that may last only one or two hours. The massive flanged wellhead represents a substantial and costly over-design of the wellhead structure for the remainder of the life of the well.
In an attempt to resolve this problem, a prior art tubing head has been designed and sold by J. M. Huber Corporation that includes an independent screwed wellhead body that is lengthened to accept lockdown screws. The lockdown screws retain a special mandrel that isolates the wellhead body from the high pressures that are encountered during formation fracturing operations. Since the mandrel is designed to seal with the inside surface of the tubular, different mandrels are required for the same nominal size tubular having different interior diameters. This special mandrel may not always be commonly available at rig sites, especially in remote locations and for short notice. While this device has achieved some marketplace acceptance, most well operations use the more expensive flanged wellhead even when high pressures are only briefly encountered during a fracturing operation.
Consequently, there remains a need for a wellhead assembly that offers the option for high pressure operation, at least on a temporary basis, but at the reduced capital investment compared to the costs normally associated with higher working pressure flanged wellheads. Those skilled in the art have long sought and will appreciate the present invention which provides solutions to these and other problems.